Liquefaction of associated gas at moderate conditions

ABSTRACT

A method is proposed for converting a portion of associated gas generated during crude oil production into a liquid form which permits the transport of a large amount of methane at moderate temperatures.

TECHNICAL FIELD

The present invention resides in the methods for recovering, treating and using natural gas.

BACKGROUND OF INVENTION

The present invention relates to a method for enhancing the value of associated gas produced in a remote location. Frequently, a quantity of gaseous hydrocarbons is produced during the production of crude oil from a crude oil resource. Historically, these gaseous hydrocarbons were often flared at the well during production of the crude, particularly when the well was in a remote location, and liquid products (such as crude oil) from the well were transported large distances to the refinery or to the market for the products.

Flaring of the gases is not acceptable, both from a resource standpoint and from an environmental standpoint, and other methods for dealing with the gases is required. When the gas quantities are large enough to make large scale gas processing economically feasible, the associated gas may be liquefied in an LNG process, compressed to high pressures in a CNG process or converted to liquid hydrocarbons in a GTL process.

U.S. Pat. No. 6,793,712 teaches forming C₂ ⁺ rich liquid in a cooling stage during the liquefaction of natural gas, and removing the C2+ rich liquid via gas-liquid separation means. As taught, the sequential cooling of the natural gas in each stage is generally controlled so as to remove as much as possible of the C₂ and higher molecular weight hydrocarbons from the gas to produce a gas stream predominating in methane and a liquid stream containing significant amounts of ethane and heavier components.

Natural gas typically contains up to 15 vol. % of hydrocarbons heavier than methane. Natural gas liquids (NGL) are comprised of ethane, propane, butane, and minor amounts of other heavy hydrocarbons. Liquefied natural gas (LNG) is comprised of at least 80 mole percent methane; it is often necessary to separate the methane from the heavier natural gas hydrocarbons. It is desirable conventionally to recover the NGL because its components have a higher value as liquid products, where they are used as petrochemical feedstocks, compared to their value as fuel gas. NGL is typically recovered from LNG streams by many well-known processes including “lean oil” adsorption, refrigerated “lean oil” absorption, and condensation at cryogenic temperatures. The most common process for recovering NGL from LNG is to pump and vaporize the LNG, and then redirect the resultant gaseous fluid to a typical industry standard turbo-expansion type cryogenic NGL recovery process.

The present process is directed to the recovery and preparation of associated gas from crude oil resources which contain relatively small amounts of gas, such that the large scale gas processing methods are uneconomical. In the process, a crude liquefied gaseous mixture is prepared to be stable at relatively moderate temperatures and pressures, while containing a high amount of valuable methane (C₁), ethane (C₂) and propane plus (C₃ ⁺) components.

SUMMARY OF THE INVENTION

The present invention provides a method for converting a portion of associated gas generated during crude oil production into a liquid form which permits the transport of a large amount of methane at moderate temperatures. Thus, a method is provided for producing a methane containing liquid at moderate temperature, the method comprising the steps of: recovering an associated gas from a crude oil production process; drying the associated gas to remove water; chilling the dried associated gas; separating the chilled dried associated gas at a target temperature and target pressure in a vapor-liquid separator into a methane lean liquid stream and a methane rich vapor stream, the methane lean liquid stream containing at least 30% C2−; and storing the methane lean liquid stream.

At the target temperature of the methane lean liquid stream which is pre-selected to permit the handling and shipping of the liquid stream at temperatures and pressures normally encountered with liquefied petroleum gas (LPG), the liquid stream contains between 30% and 70% C2− components. In this way, large amounts of methane can be shipped from a remote location to a market or refinery without requiring the extreme cryogenic conditions of LNG. In one embodiment, the methane that remains as a methane rich vapor stream may be suitably used as a utility fuel for the uses selected from the group consisting of to drive gas turbine generators, to supply power requirements for living quarters and other utilities and to energize process support equipment and gas fired heaters. The methane rich vapor may further or alternatively be used as a utility fuel to provide power for dynamic position thrusters installed on a dynamically positioned FPSO.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates the process of the invention for recovering a methane-containing liquid stream from an associated gas feed stream. The liquid stream has the properties permitting it to be stored and transported at relatively moderate temperature and at a relatively low pressure.

DETAILED DESCRIPTION OF THE INVENTION

In the present method, an associated gas is treated to prepare a liquefied gas stream, containing a high amount of C2− components, which can be stored at relatively mild conditions of temperature and pressure. Thus, in one embodiment, the liquefied gas stream produced in an offshore facility may be conveyed through commercially available hoses and transported to shore in a conventional LPG tanker and/or a modified supply boat and/or a modified crude oil shuttle tanker. For example, LPG tankers typically have the capability of transporting liquefied gases at conditions of temperatures greater than −55° F. and at pressure below 500 psia.

As used here, C1 refers to a hydrocarbon molecule containing one carbon atom. Methane is an illustrative example. C2 refers to a hydrocarbon molecule containing two carbon atoms. Ethane is an illustrative example. C3 refers to a hydrocarbon molecule containing three carbon atoms. Propane is an illustrative example. C4 refers to a hydrocarbon molecule containing four carbon atoms. Butane is an illustrative example. C5 refers to a hydrocarbon molecule containing five carbon atoms. Pentane is an illustrative example. C6 refers to a hydrocarbon molecule containing six carbon atoms. Hexane is an illustrative example. Molecules with larger numbers of carbon atoms are defined accordingly. As used here, LPG is a term of art referring to a liquid phase mixture comprising primarily C3 and C4 components. LNG is a term of art referring to a liquid phase mixture comprising primarily C1 components, with lesser amounts of C2 components. Natural gas liquids, NGL, is a term of art referring to a liquid phase mixture comprising principally C4+ components.

As used herein, C2+ represents hydrocarbons containing two or more carbon atoms per molecule. Non-limiting exemplary C2+ hydrocarbons include ethane (C2H6), propane (C3H8), butane (C4H10), pentane (C5H12), hexane (C6H14), heptane (C7H16), octane (C8H18), and cyclic or unsaturated variants thereof. C2− represents hydrocarbons containing two or fewer carbon atoms per molecule. C3+, C4+ are defined accordingly.

As an overview, FIG. 1 illustrates a preferred exemplary embodiment utilizing the method of the present invention. An associated gas is recovered in step 10 from a crude oil production process. Typically, gas stream 15 is delivered to the gas processing system at a pressure greater than 250 psia, or greater than 500 psia, or even greater than 1000 psia. These pressures can be obtained naturally from a gas well or obtained by adding energy through the use of one or more compressors. Thus, in one embodiment, the entire process is maintained without no additional pressurization of the gas or liquid streams during the; process. In a separate embodiment, a pump or compressor is installed in the process. For example, the compressor (not shown in FIG. 1) may be installed to pressurize, for example, the gas in stream 15, or in stream 25 or in stream 45. The choice of stream is an engineering choice. However, it is preferred that the produced gas 15 prior to dehydration, or the dried stream 25 prior to chilling, be increased in pressure up to a target pressure. In an embodiment of the invention, the target pressure is selected to ensure that a liquid methane lean stream be produced in the process having a temperature in the range of between −55° F. and 5° F., and a pressure of less than 500 psia.

The associated gas (15) is then dried to remove water in step 20. The dried associated gas (25) is pressurized in step 30 and then chilled in step 40 to liquefy a portion thereof. The chilled stream (45) comprising both a liquid portion and a gaseous portion is separated in step 50 into a methane rich vapor stream (55) and a methane lean liquid stream (57), which is stored in storage vessel (60). As shown in the embodiment illustrated in FIG. 1, at least a portion of the chilled methane rich vapor stream (55) is passed to the chilling step (40) to cool the incoming dried associated gas prior to its chilling. The methane lean stream (57) has a lower concentration of methane than the associated gas feed (15), and the methane rich stream (55) has a higher concentration of methane than the associated gas feed (15). In one embodiment, the methane lean stream is a liquid stream containing at least 40% C2−, while remaining stable to volatilization at the moderate temperatures and pressures of the process. Thus, the methane lean stream can be stored in insulated containers and transported at relatively mild conditions without significant loss to evaporation. The methane rich vapor stream may be used, for example, for providing power, for reinjection into the reservoir, and the like.

Among other factors, the present invention is based on the discovery that heavy gaseous hydrocarbons condensed from an associated gas can be used to absorb light gaseous hydrocarbons, such as methane and ethane, while maintaining a relatively low vapor pressure. The naturally occurring heavy ends in the condensed stream allow methanes and ethanes to condense and be stored as liquids in a multi-component mixture at moderate pressures and temperatures. At such conditions, CO2 removal, complex chilling/cold recovery process, distillation/fractionation process and handling of ultra-low temperature cryogenic liquids (such as LNG) is avoided, making the offshore (and/or) remote facility simple and safe to operate and maintain. This unfinished liquid product called “Liquefied Heavy Gas” can be easily transported from a remote (and/or) offshore location and processed further at an onshore processing facility into finished products such as LPG, natural gas liquids and pipeline export gas. The remaining uncondensed hydrocarbons are useful for satisfying internal fuel requirements.

For example, the feed gas to the process can contain CO2 at levels up to 5% when the heavy liquid product is prepared at the target temperature and pressure, with CO2 levels of up to 2% being preferred.

Associated gas is a natural gas which is found in association with crude oil, either dissolved in the oil or as a cap of free gas above the oil. Associated gas typically separates from the crude oil during production, and is recovered as a separate gaseous phase from the crude oil liquid phase. The characteristics of the associated gas depends on the field from which it is recovered, the nature of the crude oil with which it is produced, and the temperature and pressure of the crude oil as it is produced and stored. In general, associated gas comprises C1+ components, and may include trace amounts of hydrocarbons up to C10 or even higher. Most of the hydrocarbons in associated gas are in the C1-C6 range.

Associated gas is separated from the produced crude at any time during the production, handling and storage of the crude, though most is recovered as a separate phase during crude production from the reservoir. Methods for recovering associated gas are well known and practiced in most producing wells.

The present process is beneficially practiced for processing associated gas produced in a remote location. Such remote locations are sufficiently separated from the market that delivering the gas to market through a pipeline is expensive and/or technically difficult relative to transporting the associated gas by water, including ships, barges, tankers and the like or by overland vehicle, including by trucks, trains and the like.

In general, associated gas contains water vapor, which is preferably removed prior to chilling. Methods for removing water from associated gas are well known. In one illustrative embodiment, the water is removed using glycol as the absorbent, optionally in combination with a molecular sieve to reduce the water to the levels required by the process. Thus, water is removed from natural gas upstream of the cryogenic plant by glycol dehydration (absorption) followed by a molecular sieve (adsorption) bed. Alternatively, a molecular sieve bed alone, or in combination with other conventional methods, may be used to remove the water. Molecular sieve dehydration units are normally installed upstream of the cryogenic plant to eliminate the water before the gas enters the cooling train. An exemplary molecular sieve which is useful for this drying step is an X-type zeolite adsorbent.

The dried associated gas is chilled to condense a portion of the gas, forming a partially liquid phase product. The temperature to which the associated gas is chilled depends on a number of factors, including the amount of the methane rich vapor phase component needed for power, and the temperature and pressure of the methane lean liquid component which can be tolerated while the liquid component is being transported from the remote site. In one embodiment of the process, the associated gas is chilled to a target temperature, which is pre-selected to produce a liquid phase methane lean product which can be shipped to a shuttle tanker (or supply boat) using commercially available marine hoses. Associated gas chilling is achieved using, for example, an adiabatic process (such as Joule Thomson process), an isentropic process (turbo-expander) or an external refrigeration process. Storing and shipping the methane lean liquid component is facilitated when the component is stored under pressure. As with the temperature, a target pressure is pre-selected to maintain the methane lean component in the liquid phase during storage and shipping. Pressurizing the associated gas is typically done prior to the chilling step. In another embodiment, the temperature and pressure conditions of the separator are set such that the volumetric rate of methane rich gas leaving the separator corresponds to the flowrate required to satisfy internal fuel gas consumption, with the remainder being condensed as liquefied heavy gas which is stored in pressurized vessel(s) or containers and transported to consumers.

The chilled stream from the chilling step is then separated into a methane lean liquid stream and a methane rich vapor stream using a liquid vapor separator. The temperature and pressure of the separation are set by targets desired for shipping the liquid stream. In one embodiment, the target temperature of the methane lean liquid phase is greater than −55° F., and typically ranges from 5° F. to −50° F. (depending upon the demand of the internal fuel gas requirement). Likewise, while the process can be used to prepare a methane lean liquid phase having a pressure of less than 750 psia, a pressure of less than 500 psia is preferred, and a pressure in the range of 220 psia to 450 psia is preferred. A higher internal fuel gas demand can be met by increasing the separator temperature, thereby producing more gas and correspondingly less liquefied heavy gas. In one embodiment, the separator pressure is set at a pressure lower than the storage vessel/container maximum allowable operating pressure to account for possible increases in pressure over time due to boil off gas generated from heat ingress into the system.

In one embodiment, the separation is performed in a single stage vapor liquid separation, and without fractional distillation. Gravity separators, centrifugal separators and the like are ideal for the separation. Though having a reduced methane content relative to the associated gas feed to the process, the methane lean liquid phase contains a significant amount of C2− material. Generally, the methane lean liquid contains at least 30% C2−, more preferably in the range of 30% to 65% C2−, and most preferably in the range of 40 to 60% C2−. The methane rich vapor contains less than 30% C2+, preferably less than 25% C2+ and most preferably less 15% C2+. As used herein, percentage amounts are referenced to molar percentages, unless stated otherwise. The storage vessel/container is generally thermally insulated to minimize heat ingress and thereby delay the rise in pressure over time. The naturally occurring C3+ heavy components in the liquids assist in condensing the methane and ethane components at relatively moderate temperatures which may then allow the use of commercially available flexible marine hoses to unload the liquefied heavy gas from an offshore facility to supply boats/shuttle tanker.

The methane lean liquid phase is stored at a target temperature and at a target pressure. In one embodiment, the target temperature of the methane lean liquid phase is greater than −55° F., and typically ranges from 5° F. to −50° F. (depending upon the demand of the internal fuel gas requirement). Likewise, while the process can be used to prepare a methane lean liquid phase having a pressure of less than 750 psia, a pressure of less than 500 psia is preferred, and a pressure in the range of 220 psia to 450 psia is preferred.

The gaseous portion which is separated from the chilled associated gases is methane rich relative to the dried associated gases. In this preferred exemplary embodiment, this chilled gas portion is used to cool incoming dried associated gas which is to be sent to the chilling step. After removing heat, this methane rich gas portion may then be used to energize the production facility, such as by installing gas turbine based power generators and/or gas engine/turbine based compressor drivers and/or gas fired heaters to satisfy process heat load. To maximize use of gas as internal fuel for floating offshore facilities such as a Dynamically Positioned FPSO, all marine power requirements (including dynamic positioning thrusters) under operations using the methane rich stream are sourced from topsides gas turbine generators (in lieu of utilizing the ship's marine fuel oil fired power generators) which also provide power to the production facilities. These power generators may have dual fuel capability to support start-up and other off design cases. Alternatively, if surplus gaseous methane rich stream still exists after satisfying internal fuel consumption then a portion of gas may be converted to CNG. Or surplus gas is converted to additional power and exported to third party else, a portion could be used for needed energy purposes with remainder converted to CNG. Moreover, a portion of the gaseous portion could be reinjected in a subterranean formation.

The liquefied heavy gas is an unfinished product which contains a mixture of components ranging from methane to C5+ components which is then transported to an onshore gas processing facility or a refinery which fractionates the liquefied heavy gas into finished products such as pipeline specification gas, LPG and stabilized NGL. 

1. A method for producing a methane containing liquid at moderate temperature, the method comprising the steps of: a. recovering an associated gas from a crude oil production process; b. drying the associated gas to remove water; c. chilling the dried associated gas; d. separating the chilled dried associated gas at a target temperature and target pressure in a vapor-liquid separator into a methane lean liquid stream and a methane rich vapor stream, the methane lean liquid stream containing at least 30% C₂−; and e. storing the methane lean liquid stream.
 2. The method of claim 1 wherein the target temperature is between 5° F. and −55° F. and the target pressure is less than 750 psia.
 3. The method of claim 2 wherein the target temperature is greater than −55° F.
 4. The method of claim 2 wherein the pressure is less than 500 psia;
 5. The method of claim 2 wherein the pressure is in the range of between 220 psia to 450 psia.
 6. The method of claim 1, wherein the methane lean liquid stream contains between 30% and 70% C₂− components.
 7. The method of claim 6, wherein the methane lean liquid stream contains between 40 and 60% C₂− components.
 8. The method of claim 1 wherein the methane rich vapor stream comprises less than 30% C₂+ hydrocarbons.
 9. The method of claim 6 wherein the methane rich vapor stream comprises less than 15% C₂+ hydrocarbons.
 10. The method of claim 1 wherein the associated feed gas comprises greater than 30% C₂+ hydrocarbons.
 11. The method of claim 8, wherein the associated feed gas comprises greater than 40% C₂+ hydrocarbons.
 12. The method of claim 1 wherein the dew point of the dried associated gas is less than the target temperature.
 13. The method of claim 1, further comprising using the methane rich vapor as a utility fuel for the uses selected from the group consisting of to drive gas turbine generators, to supply power requirements for living quarters and other utilities and to energize process support equipment and gas fired heaters
 14. The method of claim 1, further comprising using the methane rich vapor as a utility fuel to provide power for dynamic position thrusters installed on a dynamically positioned FPSO. 